1. Field of the Invention
In general, the invention relates to techniques to increase and/or optimize production of a reservoir.
2. Background Art
The following terms are defined below for clarification and are used to describe the drawings and embodiments of the invention:
The “formation” corresponds to a subterranean body of rock that is sufficiently distinctive and continuous. The word formation is often used interchangeably with the word reservoir.
A “reservoir” is a formation or a portion of a formation that includes sufficient permeability and porosity to hold and transmit fluids, such as hydrocarbons or water.
The “porosity” of the reservoir is the pore space between the rock grains of the formation that may contain fluid.
The “permeability” of the reservoir is a measurement of how readily fluid flows through the reservoir.
A “fracture” is a crack or surface of breakage within rock not related to foliation or cleavage in metamorphic rock along which there has been no movement. A fracture along which there has been displacement is a fault. When walls of a fracture have moved only normal to each other, the fracture is called a joint. Fractures may enhance permeability of rocks greatly by connecting pores together, and for that reason, fractures are induced mechanically in some reservoirs in order to boost hydrocarbon flow.
The word “conductivity” is often used to describe the permeability of a fracture.
There are typically three main phases that are undertaken to obtain hydrocarbons from a given field of development or on a per well basis. The phases are exploration, appraisal and production. During exploration one or more subterranean volumes (i.e., formations or reservoirs) are identified that may include fluids in an economic quantity.
Following successful exploration, the appraisal phase is conducted. During the appraisal phase, operations, such as drilling wells, are performed to determine the size of the oil or gas field and how to develop the oil or gas field. After the appraisal phase is complete, the production phase is initiated. During the production phase fluids are produced from the oil or gas field.
More specifically, the production phase involves producing fluids from a reservoir. The wellbore is created by a drilling operation. Once the drilling operation is complete and the wellbore is formed, completion equipment is installed in the wellbore and the fluids are allowed to flow from the reservoir to surface production facilities.
Production may be enhanced using a variety of techniques, including well stimulation, which may include acidizing the well or hydraulically fracturing the well to enhance formation permeability. In some reservoirs, especially high modulus reservoirs such as tight gas shales, tight sands or naturally unfractured carbonates, fracture surface area, either natural or induced, may be directly correlated to well production, that is, the rate at which fluids may be produced from the reservoir. As such, it may be beneficial to locate such high modulus reservoirs that include a large fracture surface area. In cases where the high modulus reservoir does not include fractures (or a sufficient fracture surface area for economic production), the high modulus reservoir may be fractured to increase the fracture surface area. In high modulus rocks small deformations result in high stresses with a large radius of influence. Accordingly, shear stresses and shear displacements in these reservoirs may be developed by promoting asymmetries, for example by introducing zones of compliance or high stiffness in the region to be fractured.
While the fracturing increases the fracture surface area, the fractures must remain open for the fluid to flow from the reservoir to the surface. If the fractures resulting from the fracturing are simple, then proppant (such as, but not limited to, sand, resin-coated sand or high-strength ceramic or other materials) may be used keep the fracture from closing and to maintain improved conductivity.
Highly complex fractures generally give improved production rates. While the production of a fracture with high complexity and, thus, high surface area may theoretically be matched by a simple fracture of equivalent surface area, creating multiple simpler fractures (for example, by increasing the number of stages) may provide similar results to a complex fracture. However, this approach may be expensive and logistically complex. An additional benefit of complex fracturing is the resultant higher fracture density per unit of reservoir volume, which increases the overall reservoir recovery. In other words, not only is there a faster rate of production of the fluids that are generally recoverable, but more of the oil or gas in the reservoir may be recovered instead of being left behind, as would otherwise occur. However, if the fractures resulting from the fracturing are complex (e.g., branched), then using proppant may not be sufficient to prop the fractures. The proppant may not, for example, be adequately delivered to all of the branches of the fracture, or the density of the proppant delivered might be insufficient to maintain conductivity. Those portions of the fracture might then close, thereby reducing fracture conductivity.
While reservoirs have been stimulated for many decades, a need exists for a method, apparatus and system to determine the particular conditions affecting the treatment of the individual reservoir (e.g., near-wellbore effects, reservoir heterogeneity and textural complexity, in-situ stress setting, rock-fluid interactions). A need exists for a method, apparatus and system to detect the conditions required for generating induced fracture complexity, high fracture density, and large surface area during fracturing, and use this data to anticipate fracture geometry and adapt all other aspects of the design to optimize production and hydrocarbon recovery. A need exists for a method, apparatus and system to identify unique conditions of reservoir properties, in-situ stress, and completion settings to determine a design of fracture treatments that specifically adapt to these conditions. For example, the positive and negative consequences of induced fracture complexity, e.g., the increase in surface area for flow and the increase of the drainage area, versus the increase in surface area for detrimental rock-fluid interactions, the increase in tortuosity of the flow paths and its detrimental effect on proppant transport, proppant placement, and in the associated difficulties in preserving fracture conductivity are all factors which, when accounted for, allow adapting the fracture design accordingly (e.g., changing fluids, additives and pumping conditions). A need exists for a method, apparatus and system to promote the self-propping of complex fractures and complex fractured regions. This is important because the more complex and extensive the produced fracture, the more tortuous the flow path and, accordingly the more difficult it is to deliver proppant for preserving fracture conductivity. A need exists for a method, apparatus and system to identify operational techniques for enhancing the self-propping of fractures and for improving the distribution of proppant along the fracture, thus retaining fracture conductivity and enhancing well production. A need exists for a method, apparatus and system for monitoring these effects (e.g., via real-time micro-seismic emission, surface deformations, or equivalent), to adapt in real-time, to the conditions of the treatment, and to validate the fracture geometry and complexity anticipated during the evaluation phase. A need exists for a method, apparatus and system to allow data collection for post analysis evaluation, to continuously improve the methodology by including complexities that may be local to a particular field or segment of the field, or previously not anticipated.